Subsea drilling typically involves rotating a drill bit from fixed or floating installation at the water surface or via a down hole motor at the remote end of a tubular drill string. It involves pumping a fluid down the inside of the tubular drill string, through the drill bit, and circulating this fluid continuously back to surface via the drilled space between the hole/drill string, referred to as the wellbore annulus, and the riser/drill string, referred to as the riser annulus. The drill string extends down through the internal bore of the riser pipe and into the wellbore, with the riser connecting the subsea blow out preventer (SSBOP) on the ocean floor to the floating installation at surface, thus providing a flow conduit for the drilling fluid and cuttings returns to be returned to the surface to the rig's fluid treatment system. The drill string is comprised of sections of tubular joints connected end to end, and their respective outside diameter depends on the geometry of the hole being drilled and their effect on the fluid hydraulics in the wellbore.
Conventionally, the well bore is open to atmospheric pressure and there is no surface applied pressure or other pressure existing within the system. The drill pipe rotates freely without any sealing elements imposed or acting on it at the surface, and flow is diverted at atmospheric pressure back to the rig's fluid treatment and storage system.
During drilling, responses and reactions to drilling parameters are based on the wellbore conditions from data streams at surface and down hole from drilling tools. Data streams such as weight on bit (WOB), rate of penetration (ROP), bit location, bottom hole pressure (BHP) and temperature (BHT), rotary RPM, drill pipe pressure or standpipe pressure (SPP), drilling injection rate or pump strokes (SPM), return flow rate, and applied surface pressure or choke pressure are used to make decisions for the adjustment of drilling parameters. Thus, drilling decisions use these in addition to practical experience to guide drilling throughout the entire drilling operation. Furthermore, high level or safety critical decisions over the course of the well are based on the available data streams, on site meetings, and verbal operating orders to rig and service personnel—a process prone to error. Time constraints, communication breakdown through misinterpretation or misunderstanding of standing orders, or other important restraints or limitations such as formation characteristics or equipment limitations may get overlooked. This leads to an inefficient decision-to-action process, with a large degree of human error and a potential impact to productive time.
The bit penetrates its way through layers of underground formations until it reaches target prospects—rocks which contain hydrocarbons at a given temperature and pressure. These hydrocarbons are contained within the pore space of the rock i.e. the void space and can contain water, oil, and gas constituents—referred to as reservoirs. Due to overburden forces from layers of rock above, these reservoir fluids are contained and trapped within the pore space at a known or unknown pressure, referred to as pore pressure. An unplanned inflow of these reservoir fluids is well known in the art, and is referred to as a formation influx, or loss, and this may lead to a kick, commonly called a well control incident or event. For the purposes of this document, the words formation influx, loss and kick are viewed as interchangeable.
Furthermore, the infiltration of gas into the riser system creates an extremely hazardous situation, as the gas is now above the main safety barrier i.e. the subsea BOP and will continue to expand and increase in velocity as it migrates or circulates up the riser. This leads to the violent displacement/unloading and/or evacuation of the liquid volume from the riser. Ultimately, this could lead to an uncontrolled blow out of gas through the rig rotary table, which could be catastrophic to people, equipment and the environment.
Conventional methods of kick and loss detection and subsequent well control procedures are outdated and not particularly well suited for effectively monitoring and safely controlling these conditions in deep and ultra-deep water drilling especially for High Pressure and High Temperature (HPHT) wells. Well control event detection and subsequent control measures are time critical, and the longer the time lapse before a response is initiated, the bigger the subsequent influx volume, and the greater the resulting problems. This is even more critical when carrying out pre-salt drilling with fractured carbonates and higher pressure reservoirs, where the drilling window between the pore pressure and fracture pressure is quite narrow. The pitch and roll of the rig in response to the heave of the ocean results in changes to the return flow rate and variations in the active fluid system tank levels that can mask kick and loss events, resulting in a further time lapse before detection and appropriate response is implemented. Since time is critical when mitigating such events, early and accurate detection is essential.
Conventionally, safety critical procedures such as kick response have been manual decisions based on the interpretation of data streams from the rig that are compiled into the central control and processing unit, also referred to as the main drilling control and monitoring system (DCMS). Analysis of data over time within the main drilling control system alarms the rig of changes in flow or pressure parameters that may be positive kick indicators, but the final decision to react and implement the well shut in procedure is given by a manual verbal order followed by manual operations for the rig pumps, draw works, subsea BOP, and choke manifold. The standard sensors for offshore kick and loss detection are including but not limited to standpipe pressure, ROP, trip tank volume, active pit volume, return line flow rate, injected flow rate or pump strokes, drilling torque, drillstring weight, and gas detection at the shakers. All sensor data from the rig's standard kick detection system is processed through the rig's central processing unit (CPU), and the kick detection sensors form an integral part of the DCMS.
Third party Mudlogging services integrate additional sensors within the rig layout, heightening the monitoring capabilities of the rig and keeping existing rig sensors in check. Mudloggers connect various sensors and install specialized equipment to monitor or “log” drilling activity, monitoring for changes or trends in drilling parameters which may implicate kick or loss events. Mudloggers further monitor and interpret the well indicators in the mud returns during the drilling process, and at regular intervals log properties such as ROP, mud weight, flow line temperature, oil indicators, SPP, pump rate or SPM, gas analysis of shaker gas, lithology (rock type) of the drilled cuttings, and other data in addition to the existing rig sensor network. The Mudlogging system functions through an independent CPU, and operates externally to the DCMS.
Other third party companies provide downhole data, such as Measurement While Drilling (MWD) and directional drilling services. Formation data transmitted to surface from electronic downhole tools installed near the bit in the Bottom Hole Assembly (BHA), such as BHP, BHT, bit orientation, downhole WOB, and lithology. Changes in BHT and BHP can be positive indicators for kicks during drilling.
Conventionally, these are the standard independent monitoring systems providing the kick detection system on a floating installation.
Various methods of automation of drill processes for the optimisation of drilling are also known from other prior art drilling system.
During managed pressure drilling (MPD), additional equipment is installed at surface to create a closed loop drilling system which allows the application of applied surface or choke pressure to the riser and wellbore. Fluids are diverted through a flow spool installed within the riser, and use a pressure containment device to seal around the drill pipe to divert all returned flow to a flow line connected to the flow spool. All flow is routed through a mud gas separator (MGS) which degasses the fluid before it returns to the rig's fluid system. The MPD system uses choke pressure to maintain the BHP constant within the drilling window during drilling, circulating, and tripping periods. MPD is normally an automated system, using a number of drilling related parameters, including down hole data from the MWD/Directional service provider, to adjust the choke pressure to remain within the drilling window while simultaneously using advanced kick and loss detection modules to monitor the riser and wellbore annulus for loss and gain events. MPD services are usually provided through a third party contractor on the rig, however, more recently offshore drilling contractors are integrating MPD equipment as permanent infrastructure into their fleets. This is due to the growing demand for MPD techniques to safely and economically drill increasingly challenging reservoirs in deep and ultra-deep water. Such automated systems are described in patents U.S. Pat. No. 6,233,524 and U.S. Pat. No. 5,842,149, and adjust their parameters automatically or via a manual operator adjustment.
An automated drilling method is disclosed in patent application US2007/0246261, and describes a system where the AC electric motors which drive various drilling equipment are controlled by PLC's. A central control system monitors the variable frequency drive (VFD) of the electric motors, and utilizes user inputs to control the speed and torque of the pumps, draw works, and top drive systems used in drilling. This system is integrated into the rig's DCMS with a PLC system, allowing input of desired drilling parameters through a human machine interface (HMI). However, the system described in this application is applied to drilling and tripping optimization and not safety critical equipment functionality and well control safety.
Patent application WO 2013/082498 discloses another automated drilling system and method, using drilling parameter sensors in communication with a sensor application that generates processed data from raw data received from the drilling parameter sensor. A process application generates a command or instruction based on the processed data, and a priority controller evaluates the instruction before releasing the instruction to an equipment controller which then automatically manipulates one or more drilling parameters such as pump speed, WOB, etc. The described system is embedded within the DCMS and operates within its framework, is in bidirectional communication with drilling components, and can provide operating instructions to safety critical equipment such as BOP's in response to drilling parameters monitored by its sensors. However, it is stated the disclosed system is directed to control drilling processes, extending its application to MPD, kick detection, and drilling efficiency. Thus, the system described in this application is applied to drilling optimization and not safety critical equipment functionality and well control safety.
An automated event detection and response system for MPD is described in patent application US2012/0241217. This application discloses an automated drilling method for an MPD system that includes a drilling event detection (i.e. kick, loss, plugged choke, etc.) through processes of comparing parameter signatures generated during drilling to event signatures indicative of the drilling event. The proposed system automatically controls the drilling operation in response to a partial or full match between the event and parameter signatures. A sensor system on the rig continuously transmits data to a central CPU, and what occurs in the present drilling operation (the drilling parameter signatures) is compared to a set of drilling event signatures. The data streams are used to supply data indicative of the real time drilling properties, which is then used to determine drilling parameters of interest. The data is analysed to examine how each parameter is changing over time, and given appropriate values to generate drilling parameter signatures.
The event signatures do not represent what is occurring real time during drilling and are representative of what the drilling parameter behaviours are when the event happens, i.e. the expected data trends during a kick. The event and parameter signatures, when matched or partially matched, automatically adjust the choke or other parameters with no human intervention. The disclosed system is the progression towards automated kick detection, but operates on an independent CPU which is external to the rig's DCMS. Safety critical equipment such as the subsea BOP is not automatically operated and manual decisions are required for implementing the well control safety procedures.
Further progression of automated rig processes, remote control and manipulation of drilling parameters, and remote rig supervisory control are disclosed in patent applications US2010/0147589A1 and WO2004/012040A2.
Patent application US2010/0147589A1 describes a system and method for rig supervisory control through automation that includes replication and aggregation of supervisory control panels, mechanisms to manipulate these panels using smart algorithms, and a method and technique to access the supervisory control panels from a remote location. It includes a record, edit and playback function allowing an efficient operational sequence, such as bringing the pumps online, to be re-used on the rig or “played back” through its execution through the main DCMS.
Patent application WO2004/012040A2 describes a method for providing an automated rig control management system utilizing a hierarchical and authenticated communication interface to various third party contractor and drilling contractor parameters. It uses control models/algorithms for allocating and regulating drilling parameters according to constraints within the control management system.
However, the application for these systems and methods is for drilling optimization versus safety critical functionality. Decisions to change parameters, adjust equipment, or implement any given procedure remain a manual process.
Furthermore, the systems disclosed in the above patents are only useful if the data flow streams are handled and managed properly.
A system and method disclosed in patent application US2012/0274475 describes a sensor system on an offshore installation specifically for kick detection, and used to automatically react upon a confirmed kick event detected during drilling. Its control logic monitors, warns, and acts based on sensor input data to automatically detect and control a kick without requiring manual based decisions to be made by operations personnel. The sensor data is acquired and processed within a central CPU specific to the SSBOP, and using a step level decision to process the safety critical equipment such as the SSBOP and emergency disconnect system, which are automatically functioned in response to positive kick indicators from the sensors. However, the SSBOP CPU is external to the rig's DCMS architecture and the system disclosed in this patent is only useful if the data flow streams are handled and managed properly.
The rig's DCMS is a critical element for the safe and efficient operation of the rig throughout the drilling process, and is a software based system that acquires and compiles all sensor inputs and equipment controls into a central module for processing, display, and manipulation from a central console. Data outputs are displayed at various points on the rig such as the Company representative's office and rig manager's office. The CPU may be a single or series of computers, mini-computers, or microprocessors and includes programmed algorithms to perform automated commands which manipulate the rig equipment components. The DCMS includes memory storage devices, input and output devices, and operates on programmable logic controllers (PLC) well known in the art. They are generally connected to a server that responds to requests across a computer network to provide, or help to provide, a network service on the rig, and can be connected to and accessed remotely from, for example, offices onshore.
Such systems are provided through Aker Solutions MH control systems, who produce state of the art DCMS. The system accomplishes a high level of automation, such as remote control of equipment and systems, synchronization of equipment, fully automatic modes, and fully automatic modes with synchronized closed circuit television (CCTV) cameras and predefined drilling operation sequences through its configuration automatic drilling system (CADS). Predefined drilling sequences allow standardized operations and improve safety on the rig, and include smart zone management, set points, interlocks, and other safety features built into the software for efficient execution.
Aker's MH Operating Chair is the main human machine interface (HMI) for their DCMS, and allows total control of the rig's drilling parameters from a central console. It enables a full multi-user selection between the drilling operation modes, and focuses all drilling sensor and equipment data streams on the rig to this central monitoring location, normally situated in the driller's cabin. A touch screen interface is normally used for data entry and manipulation of equipment. Other DCMS and HMI systems may use a mouse, keyboard, and monitor hardware configuration.
The Aker MH DCMS and Operating Chair integrates mechatronics, a design process that includes a combination of mechanical engineering, electrical engineering, control engineering and computer engineering, to automatically manipulate and control equipment on the rig. These include, but are not limited to, robotic machines used for pipe handling and racking, crane operation, rig pump function, draw works operation, top drive function, and rotary table slips. However, the operation of the safety critical equipment, such as the SSBOP, is still performed manually during a kick event.
Within the AKER DCMS, the rig safety systems are provided with automated mechanical safeguards, disclosed in patent GB 2,422,913. The movements of mechanical devices within the automated system relative to the movements of other mechanical devices are prevented from colliding through the algorithms within the DCMS. A minimize function is implemented in the programmable logic controller (PLC) based on actual and calculated stop distances of the machine and used to stop machines before they collide. This mechanical safety system is extended to pipe handling on the rig, for example, preventing the hoisting of the drillstring if the elevators and the roughneck are both locked on the drillstring.
An enhanced kick detection sensor and monitoring system has been developed by the applicant, referred to as the Deepwater Kick Detection system (DKDS). This DKDS adds an additional, but more precise, third party sensor and monitoring system to the rig for enhanced kick and loss detection while operating in deep and ultra-deep water. A schematic illustration of a prior art drilling system including a DKDS is illustrated in FIG. 1, which shows a current AKER DCMS implemented on an offshore rig, revealing the various modules governing the rig systems, normal operating safety systems for the rig systems, and the well safety systems within the DCMS architecture.
The DCMS 1 consists of a central processing unit (CPU) 2 which may be a single or multiple microprocessors with memory and input and output devices, and includes Programmable Logic Controllers (PLC) to manipulate equipment. The CPU 2 is operably connected with mechanical, pneumatic and hydraulic controls of the offshore rig system modules 5, the rig's normal operating safety system module 7, and the well safety systems module 10. An internal communication bus may be in bidirectional communication with one or more of these modules'sensors or processes. A network interface allows bidirectional communication with external sources and users on the offshore installation, or alternately remotely to offices onshore. This permits remote monitoring of current processes during drilling.
The rig system module 5 comprises a multitude of mechanical, hydraulic, and/or pneumatic systems on the floating installation, including, but are not limited to, the drilling system (draw works, pumps, rotary table etc), the ballast tanks of the vessel, the riser tensioning system, the heave compensation system, and pipe handling equipment.
The rig's normal operating safety system module 7 typically comprises sensors 7A such as fluid level, fluid volume, pressure and temperature sensors, which monitor the mechanical systems operating on the rig, and an anticollision system 7B which is configured to detect if two pipe handling machines are moving towards one another. The anti-collision system is a feature provided within the control system which prevents pipe handling equipment from colliding during simultaneous operations that deal with the movement of drilling tubulars on the rig.
The fundamental module of the DCMS 1 is the well safety systems module 10 while modules 5 and 7 are the mechanical modules of the DCMS 1. It is the safety critical systems governed by the well safety module 10 that provide the necessary safeguards and protection to the environment, equipment and people from the risks of the wellbore being drilled with the floating installation. In this example, the well safety system module 10 comprises the SSBOP 11 and associated sensors 11, a diverter 12 and associated sensors 12a, a rig kick detection system 13 and associated sensors 13a, a riser gas handling/quick closing annular BOP (RGH/QCA) system and associated sensors 14b and CPU 14a, the DKDS 15 and associated sensors 15b and CPU 15a, and a mudlogging system and associated sensors 16b and CPU 16a. Whilst the RGH/QCA 14, DKDS 15 and Mudlogging 16 systems each have their own CPU 14A, 15A, 16A, the rig kick detection system 13 uses the central CPU 2, and hence its sensors 13a are in communication with the central CPU 2.
The systems operating within the architecture of the DCMS 10 are the SSBOP system 11 and associated sensors 11A, the diverter system 12 and associated sensors 12A, and the rig kick detection system 13 and associated sensors 13A. To enhance the kick detection and response of the floating installation, the Mudlogging system 16, its CPU 16A and associated sensors 16B, the DKDS 15, its CPU 15A and associated sensors 15B, and the RGH/QCA system 14, its CPU 14A and associated sensors 14B are three separate third party systems operating externally to the DCMS CPU 2 through their own independent CPU's 14A, 15A and 16A.
An example of a Riser Gas Handling (RGH) system is described in patent application WO2013153135. The RGH is an operating system for safely handling large influxes of gas in the riser and the resultant pressurized flow from the riser, and involves operating a rapidly closing riser sealing apparatus, referred to as the Quick Closing Annular (QCA), to seal off the riser at a point above a flow spool provided in riser. The core concept of the RGH is reducing the total kick volume and recovery time for any given kick event, referred to as Influx Volume Reduction (IVR), resulting in reducing the time and cost of well control incidents, reducing risk, and improving the management of well control. It utilises the diverting of flow through a flow spool to a choke valve provided in a riser gas handling manifold at surface, which is used to control the diverted flow from the riser to a high capacity gas rate mud gas separator (MGS) at surface. Here, the gas is safely separated from the fluid in a controlled manner and vented to atmosphere at a safe distance from the rig. The system compiles pressure, temperature and flow data into its CPU 14A, and even though an element of automation exists within its safety critical functionality, the final decision for its activation is a manual decision based on the data analysis. The resultant safety procedure upon its activation is disclosed in WO2013153135. This is an additional well safety system to the SSBOP and diverter systems on the rig, functions independently to the rig's critical safety equipment, and operates through its algorithms contained within its designated CPU 14A.
A data logger and storage device 4 is connected to the central CPU 2, and this allows the DCMS 1 to record, sort, and store all data feeds from the existing sensors on the rig. It is within the data logger and storage system 4 that the data is time stamped, presenting the data in a consistent format and allowing for the easy comparison of two or more different data records while tracking progress over time. A timestamp is the time at which an event is recorded by the CPU, not the time of the event itself. In many cases, the difference may be inconsequential—the time at which an event is recorded by a timestamp (i.e. entered into the data logger 4 file) should be close to the time of the event.
Data from sensors specific to the DCSM 1, i.e. the sensors which are connected to the main CPU 2, in this example the normal operating safety system sensors 7A, the anti-collision system 7B, the SSBOP sensors 11A, the diverter sensors 12A, and the rig kick detection sensors 13A, are sorted and stored using a detailed time stamping code assigned within the data logger and storage system 4. Using this data acquisition process, playback of an operational sequence or particular event is possible such that the DCMS 1 data can be examined closely for further analysis. The stored data within the data logger 4 can be retrieved at any time through the DCMS CPU 2.
An AKER MH Operator Chair Human Machine Interface (HMI) 3 is also connected to the central CPU 2, and is the main operator interface and control for manipulating the modules 5, 7 and 10 of the DCMS 1, described herein. The processed sensor data from the CPU 2 is transmitted and displayed on the Chair HMI 3, and manipulation of drilling parameters are achieved through commands prompted at the Chair HMI 3 and transmitted to the central CPU 2. From here, the hydraulic, pneumatic or mechanical control for the rig system module 5, normal operating safety system module 7, and/or the well safety system module 10 equipment can manipulated.
Generally all data streams are compiled through their respective CPU's and displayed on their separate remote monitors around the rig. Third party services, such as the DKDS and mudlogger systems described herein, install separate remote displays and stream their respective data in addition to the rig displays. Currently, all other sensor systems supplementary to the standard rig's sensor and monitoring system operate independently of and externally to the DCMS through their respective CPU's.
The rig system modules 5 and the normal operating safety system module 7 are generally mechanical aspects of the floating installation which govern the routine functions of the rig. These modules are linked such that the sensors 7A and anti-collision system 7B of the normal operating safety system module 7 are in fact the safety monitoring system for these functions occurring within the rig system modules 5. The bidirectional communication between these two modules 5 and 7 is performed through the CPU 2. Thus the rig safety system modules 5 receive sensor data 7A and anti-collision data 7B from the normal operating safety system module 7 through the CPU 2. All data is processed through the CPU 2 and transmitted to the Operator Chair HMI 3, and it is here where data streams are monitored and plotted and where rig system equipment manipulation is initiated. Alarms are raised at the Operator Chair HMI 3 if safety set points of any the rig systems are approached such that incidents or equipment problems are prevented. For example, if two pipe handling machines were moving towards one another the anti-collision system would detect this, an alarm would be raised at the HMI 3, and the machines would stop before they collided.
The SSBOP 11, the diverter 12, and the RGH/QCA 14 are considered the safety critical equipment of the well safety systems module 10. These are not data monitoring systems per say, but instead are the equipment and controls which provide the floating installation with its rudimentary well control safety response mechanism. Conventionally, these require manual decisions and human intervention for their operation, with the decision to function based on the kick detection data reliability from the sensors 13A, 15B and 16B of the monitoring systems 13, 15 and 16.
Hence, where the system shown in FIG. 1 is employed for advanced kick detection on floating installations three individual monitoring systems 13, 15 and 16 are used with three separate CPU's for processing their sensor data streams. However, multiple kick detection sources and data processing centres cannot be accurately defined as a well safety system. Each CPU 2, 15A, 16A produces their unique time stamped data within their associated data storage systems (not shown) from the raw data stream inputs originating from their sensors 13A, 15B and 16B. The raw data streams of each system are not compiled through a single standardized time stamping process due to the absence of a central CPU, and therefore the data quality control checking process occurring between the data streams is decentralized and not homogeneous. Thus, it is difficult to establish data reliability and quality control amongst all of the data streams being processed through each of their designated CPU's 2, 15A and 16A.
Therefore, with the system disclosed in FIG. 1, the operation of the SSBOP 11 and/or diverter 12 systems are based on questionable data reliability and quality, and therefore the degree of certainty in the decision to operate this safety critical equipment is decreased as a result. The well safety systems 11, 12, 13, 14, 15 and 16 operate individually to one another and systems 14, 15 and 16 function externally to the DCMS 1. A lack of automated processes results as the externally functioning systems 14, 15 and 16 are merely enhanced data monitoring systems requiring manual decision processes and manual functioning of the safety critical equipment. For example, the DKDS 15 may detect an influx with its sensor system 15B through the data analysis performed by its algorithms within its CPU 15A. This signals an alarm through the DKDS HMI interface (not shown), which prompts a manual decision from the operator to stop drilling and perform a flow check. If the flow check provides another positive indicator for an influx, another manual decision process is required to close the SS BOP 11. This is followed by the manual manipulation of the SS BOP 11 controls to shut in the wellbore.
Referring now to FIG. 2, this shows a schematic illustration of a modified version of the drilling system shown in FIG. 1. The modifications relate solely to the well safety systems, so in this diagram, for clarity, rig system modules 5 and the normal operating safety systems 7 are shown as External Sensor System 5, 7, and these are the same as and function in an identical manner to those described in relation to FIG. 1. Moreover, the SSBOP 11, the diverter 12, and the RGH/QCA 14 are still considered the safety critical equipment of the well safety systems module 10 and provide the identical function as described in FIG. 1. They still require manual decisions and human intervention for their operation and their functions are based on the quality control and resultant reliability of the data and sensor inputs 13A, 15B and 16B into the DKDS CPU 15A.
In the system shown in FIG. 2, the DKDS CPU 15A is the central CPU for the Mudlogging system 16 and the rig kick detection system 13, and thus the quality control check point or central acquisition point for their processed data. However, the rig kick detection system 13 continues to operate through the central CPU 2 of the DCMS 1 while the mudlogger system 16 continues to operate through its independent CPU 16A. The rig kick detection and Mudlogging raw sensor data 13A and 16B are first processed within their designated CPU's 2 and 16A before they transmit the data to the DKDS CPU 15A. Thus, it is the processed sensor data from these systems 13 and 16 which is transferred to the DKDS CPU 15A for quality control and validity checking. The raw sensor data inputs 15B of the DKDS 15 are processed within its CPU 15A. The DKDS CPU 15A ultimately becomes the central CPU for the kick detection monitoring systems.
The kick detection monitoring systems 13, 15 and 16 continue to operate externally to the DCMS 1 architecture, however. Separate CPU's 2, 15A and 16A still exist, thus creating distinct time stamped data stream inputs into the DKDS CPU 15A and resulting in different time stamping codes on the incoming data streams. The DKDS 15 would still be considered a third party monitoring system in FIG. 2, but the level of quality control on the data stream inputs 13A, 15B, 16B is improved when compared to the system disclosed in FIG. 1 and consequently enhances the data reliability. The algorithms within the DKDS CPU 15A compare and analyze the data streams from sensors 13A, 15B and 16B, and raise an alarm when there is a variance, deviation, or anomaly amongst the data.
For example, there may be stroke counter sensors installed on the rig pump for the rig kick detection system 15 and the Mudlogging system 16. These two systems combined do not enhance the detection monitoring, as stroke counters cannot calculate pump efficiency or detect loss of suction at the rig pump and operate solely on a volume displacement per stroke calculation. However, using an independent sensor installed on the suction of the rig pump, such as the highly accurate Coriolis flow meter sensor of the DKDS system 15, the actual flow rate into the pump can be measured precisely and the efficiency calculated accurately as a result. In this case, the pump strokes may indicate the correct flow rate is being injected into the drillpipe when in reality this may not be the case if pump suction issues are present. The DKDS CPU 15A would identify this within its algorithms; comparing the data stream inputs 13A 16B from the pump stroke counters of the rig kick detection 13 and Mudlogging 16 systems to the data stream inputs 15B from the Coriolis flow meter of the DKDS 15. It is at this point that an alarm would be raised through the DKDS 15 HMI (not shown).
The inability of the DKDS CPU 15A to process the raw data inputs from 13A and 16B is a disadvantage of the system presented in FIG. 2, as there are still multiple processing centres for the separate sensor data inputs 13A, 15B and 16B occurring through their independent CPU's 2, 15A and 16A. Thus a level of uncertainty still remains with respect to the data reliability and interpretation, but it is a significant improvement over the system disclosed in FIG. 1.